If crude prices, rig counts, and tight oil production demonstrate a stronger upward trend in the months to come, US shale operators may find themselves with more produced water than they bargained for.
The concern is that a surge of produced water could eat into profit margins even as oil prices improve by driving up costs for hauling and disposal. Many shale producers can ill afford a significant spending hike on such services when, according to IHS Markit, produced water management can represent half of a shale well’s operating expenses.
The severity of this issue will depend on how aggressively shale producers seek to rebound from the downturn by drilling new wells. It also will depend on how quickly they activate the estimated 4,000 oil-rich, drilled-but-uncompleted wells (DUCs) that have amassed over the past 2 years as both a cost-cutting and a production management maneuver.
“If you get a lot of new completions in a short amount of time, that means you are going to get a whole bunch of water too, and this is something that the industry needs to be thinking about and planning for,” said Piers Wells, co-founder and chief executive officer of Digital H2O, a company that uses analytics-based models to forecast oil-field water resources.
Because it is the most active and prolific shale play, the Permian Basin of Texas is already under pressure. As shown by Digital H2O’s model, the recent uptick in drilling there and in the adjacent Delaware Basin is yielding produced water volumes that are approaching what many of the disposal wells can take away.
“While they may not be at full pressure utilization today, many are getting close and, in a higher-price environment, you will see many more areas shifting into high utilization,” Wells said. “The thing that people need to be aware of is that this could all happen really, really fast.”
With far less drilling activity happening, North Dakota’s Bakken and Texas’ Eagle Ford shales are not facing quite the same situation as the Permian currently is. However, higher prices would start to change that, and there are also more than 2,000 DUCs in those two plays that if brought on line in quick succession have the potential to drive water--handling costs higher.
Produced water management is complex and expensive for shale producers partly because they have fewer options than their conventional counterparts on what to do with it. One major disadvantage is their inability to reinject into unconventional reservoirs, underscoring that disposal wells will always play an outsized role in
shale developments.
And proving that even virtuous solutions have their limits, if every shale well in the US was hydraulically fractured with recycled produced water, it would account for only a single-digit fraction of the total volume of water generated each day.
Those studying water management practices say that if operators start adopting longer-term strategies, they can gain leverage over rising wastewater costs. Their recommendations include lessening reliance on inefficient water trucks by building more water pipelines along with permanent processing and treatment facilities.
Michael Dunkel, a vice president for the engineering consultancy CH2M, has been involved with water infrastructure projects in Texas and Oklahoma and said a number of operators are on the cusp of investing more capital on this front. However, he noted that a meaningful expansion of water facilities in the shale sector will be years in the making.
“It will be slow to evolve,” he emphasized. “But 5 years from now, I am confident that there will be a lot more water infrastructure in place, both to move around source water and to interconnect disposal water, which will give greater flexibility in transporting it to different disposal wells.”
Price Matters
The place to watch will be the Permian where, according to the Baker Hughes rig count, there are more rigs turning to the right than in any other place on Earth. Having maintained solid growth throughout the downturn, the Permian is producing about 2 million B/D of oil—and about 11 million B/D of water.
Assuming that even modest gains in crude prices will encourage more drilling in the Permian, as has been the case since June, Wells said one of his firm’s clients there is expecting the prolific region to see a “wall of water” next year.
It is an assertion that the firm’s model for produced water largely agrees with—depending on prices. Wells said that if prices maintain a holding pattern of around USD 50/bbl, the model expects many disposal wells in the Permian to soon begin flirting with their upper injection limits.
The screws tighten at around USD 70/bbl. It is a price point many in the business are longing for, but Digital H2O’s model shows that it will overstrain many disposal networks in the Permian and other high-producing basins.
Wells noted that lead times to plan, permit, and drill new disposal wells could be at least a year. If demand outpaces supply, then bottlenecks could form and operators may be forced to expand their batteries of water storage tanks in order to keep producing unconstrained.
Uniquely Unconventional
There are several reasons why this particular produced water problem is unique to unconventional developments.
In the conventional world, operators have the luxury of reinjecting much of their produced water back into producing formations for waterflooding or enhanced oil recovery. Unfortunately for shale producers, neither of those practices are applicable to nanoscale permeability reservoirs, yet.
Shale wells are also drilled in much tighter clusters from pad sites than what one would see in conventional developments. This concentrates the volumes of produced water and places high demand on nearby disposal wells.
As to why operators did not plan for this earlier, during the beginning of the shale revolution they had to be somewhat nomadic, in search of the best fairways and sweet spots. This left them uncertain about exactly where future production would come from, making it hard to invest in multimillion-dollar water facilities that could not
be moved.
And lastly, while some data show that shale wells produce less water than conventional wells on average, they generate significantly more in the early life of the well. Industry-reported numbers show that a typical shale well unloads 30-40% of the water that it will churn out over an entire decade in the first year of production.
About 20% of that water, termed flowback, includes the fluids used for hydraulic fracturing, which are also growing in volume. To get more proppant into fractures, many operators are using two or three times the volume of water for fracturing that they were just 3 years ago.
Laura Capper, president of Houston-based technology consultancy CAP Resources, explained that though water cuts from shale wells begin leveling off after year 1, their front-loaded pro-duction creates especially high demand for disposal services in areas where operators are ramping up.
“What you have is a hot play, where all of a sudden you’re doing considerably more business there than you used to and you’re trying to inject the water close to the wellsite,” she said, adding that, “those neighboring injection wells are getting substantially higher injection volumes than the ones that are maybe 50 miles away and only running at say 10% of their volume capacity.”
More Pipes, More Infrastructure
When it comes to whether companies should be using trucks or pipes to transport water, Capper said investing in the latter should be a “no brainer” decision.
Operators can be charged more than USD 100 per truck per hour to move their water. Shale producers use thousands of these trucks each day to carry only 130 bbl of water a time. The trucks are hard on public roads, and represent a sizable proportion of the oilfield traffic that is attributed to an increased number of collisions around active shale plays.
Pipelines, on the other hand, can move water continuously, and -quietly, while avoiding many of the safety and environmental risks that come with trucking. Aware of these issues, a handful of larger shale producers have committed to building long networks of water pipelines.
There is also a burgeoning industry of third-party companies that act as midstream operators for produced water. A recent example of this is a 30-mile produced water pipeline that was completed in July by a company called Oilfield Water Logistics. Located in the Delaware Basin of New Mexico, several operators including Chevron will have access to the pipeline that will transport 150,000 bbl of produced water each day—which otherwise would require more than 1,000 water trucks.
In addition to a need for more pipes, more processing infrastructure will be required to handle and treat the produced water before it heads back to the subsurface. Just like a garbage disposal in a home, disposal wells run smoother and last longer when solids and other harmful elements are removed prior to injection.
And while there are a number of new well-side treatment technologies available, in this case bigger is better. Dunkel said that based on his research, small and mobile treatment systems will not be a viable answer for mid- to large-sized operators who have intensive water needs.
“The issue is actually very simple; it’s not that their capital cost is too high or that the technology itself doesn’t work—in many cases they do work well,” he said. “But if you have to have two people on site to run the system, the per barrel costs are just too high and the labor cost alone is almost a non-starter.”
Elaborating on this point, Dunkel estimated that a two-person staff for a 5,000 B/D water treatment system costs an operator about USD 5,000 a day. But if those two workers, or even a third, operated a 50,000 B/D water treatment facility, economies-of-scale kick in and make small well-side options far less attractive.
Dunkel said more operators are thinking about infrastructure today than before the downturn, but with cash flows still suffering, many have placed their plans on hold.
One exception is the water treatment and handling facility that Pioneer Natural Resources is building for its unconventional development in the Permian. Published company materials show that the facility will handle source water for fracturing operations and also recycle produced water for fracturing operations.
Speaking to the vast nature of shale developments, the permanent infrastructure is supported by 100 miles of mainline, 10 pumping stations, and an additional 500 miles of subsystem piping. Pioneer says that upon completion, the project will move the equivalent of 2,000 truckloads of water a day.
In addition to recycling, more produced water can be removed from the disposal equation if the multipurpose water facilities of the future come equipped with evaporation units.
Another idea being discussed is for shale producers to join forces and -create water management co-ops. This would help smaller companies deal with the high costs of infrastructure but it will come with competitive and regulatory challenges.
Outside of Texas, liability laws make it difficult or impossible for oil com-panies to transfer ownership of produced water unless it is heading down a disposal well. There are also operational considerations regarding who gets “first rights” to the services if a shared facility temporarily lost some of its capacity to take or supply water.
Big Limits on Recycling
If you thought stepped-up recycling efforts would be the ultimate answer to the question of what to do with produced water, you would be wrong. Though recycling is seen as important for lessening the sector’s reliance on fresh water, shale producers will never drill and complete enough wells to reuse all their produced water for hydraulic fracturing.
Capper said her analysis shows that while the majority of slickwater fracture jobs in the US now use recycled water, prior to the downturn when there was considerably more drilling taking place, the amount of water needed for fracturing vs. the total volume of produced water was fractional.
Using one of Oklahoma’s most active areas as an example, Capper’s data show that from 2012–2014 overall injection volumes in Grady County quadrupled, and daily injection volumes per disposal well tripled.
She estimated that at the peak only 3% of that briny wastewater, which in 2014 totaled 80 million barrels, was needed to support the county’s entire oil and gas operations. It could require an annual spend of USD 400 million to treat the other 97%.
“On top of that, we would have to dispose of some 16,500 railcars of associated salt,” said Capper. “No matter how you slice it, it is difficult to make the numbers work in a 100% recycling scenario—thus industry’s extreme dependence on relatively low-cost disposal wells.”
All of this highlights two things: that disposal wells will always be critical to shale developments, and that though there is a need, it will not be easy to make large volumes of recycled produced water available to outside industries.
The latter idea is termed beneficial reuse and may not always involve treating produced water to drinking quality if it is used for agriculture. In California, treated produced water has been used for many years for the irrigation of tangerines and almond groves. Texas A&M University also recently concluded a study that used treated produced water to grow cotton.
But aside from these isolated examples, this concept has not been warmly embraced or benefited from the type of extensive, and expensive, research that is needed to prove to the wider public and relevant government agencies that it can be done safely on a
larger scale.
Seismicity To Drive Costs Higher
High-rate injection activity in disposal wells connected to fault-prone formations has been cited by both industry and government experts as the primary contributing factor to induced seismicity in the US.
In areas where regulatory actions over induced seismicity have limited the supply of disposal wells, operators who want to increase production will have to spend more money hauling loads of excess water out of a quake zone.
The epicenter of this scenario is in northern Oklahoma’s Mississippi Lime play where injection-linked earthquakes have led regulators to force shut-ins or curtail injections at hundreds of disposal sites spread across more than 10,000 sq. miles. In 2016, the state experienced three 5.0-magnitude quakes while the rest of the country saw two.
“While the regulatory restrictions will undoubtedly impact operators, the problem is in fact manageable, albeit with more planning and analysis, which costs money,” said Capper, who recently contributed to a
state-by-state risk analysis on disposal wells.
She said for those companies working in potential seismic risk zones—which also include parts of Texas, Arkansas, and Ohio—the short-term solution to avoiding induced seismicity will involve a more “granular” approach to monitoring injection volumes and downhole pressures. It will also be key to understand local geological factors that may facilitate seismicity.
By taking these steps, Capper explained that observant operators should be able to stay under the thresholds thought to trigger seismicity, something she added has been proven to work in certain areas where disposal activity was restricted. Though she emphasized that it can take 18 months or more for injection reductions to result in fewer observable, or felt, earthquakes.
The idea taking shape around disposal wells in seismic risk zones is that geomechanics must trump logistics. If the industry can demonstrate an ability to self-regulate injection activity, and where necessary use a more dispersed network of disposal wells, additional government-enforced restrictions may be avoided.
“We know where these events have happened, so they should be able to manage their businesses there,” Capper said. “But it’s still going to be an additional cost burden to the industry in that you will probably have to drive your water trucks farther out, or pipe it farther away.”
